Problems related to crystallization and/or deposition of wax, hydrate and scale during production and transportation of hydrocarbons are potentially capable of causing considerable economic losses to petroleum industries. Moreover, break-through of formation water can also create problems. These losses arise through the cost of chemicals, reduced production, equipment failure, and so on. Flow assurance is thus becoming an increasing challenge as depth and step-out distances to new oil and gas fields are increasing in order to exploit more marginal fossil fuel reserves.
Gas hydrates are ice-like structures which form when water molecules assemble themselves into a ‘cage’ around a small organic molecule, for example around molecules present in oil and natural gas. Hydrates exhibit complex behaviour which represents a problem, given a large number of micro- and macro-scale phenomena involved in the process of hydrate formation, such as nucleation, crystal growth, agglomeration, break-up, entrainment and deposition along pipelines in transient multiphase flow conditions. Two distinct processes are observed in pipelines. A first process occurs at a pipeline wall with the formation of a hydrate layer (coat) as the pipeline wall is a coldest point in a system including the pipeline, providing an excellent nucleation and growth site. A second process is the formation and transport of hydrate particles in a bulk of a flow.
Current methods of preventing formation of hydrate, wax and scale may include various approaches, and combinations including:    (i) applying chemicals, for example using hydrate inhibitors such as methanol, glycol and/or new polymers injected at an upstream end of a pipeline, and wax inhibitors;    (ii) applying mechanical devices to remove or dislodge deposits, for example pigging of the pipeline;    (iii) by applying temperature changes, for example by circulating hot fluid, by applying electrical heating to the pipeline, and by applying insulation to the pipeline and an associated subsea Xmas-tree; and    (iv) by lowering an operating pressure to the pipeline, if feasible, at a constant temperature.
Hydrate inhibitor injection is today a main method of preventing formation of hydrate in transport pipelines during operation of an oil and/or gas field.
A most common way to monitor gas hydrate formation in pipelines involves using non-localized methods utilizing pVT (p=pressure, V=volume, T=temperature) measurements. In the pVT-methods, a phenomenon that gas hydrates can only form within a special pressure and temperature region (namely a “stability zone”) is exploited in order to monitor the pipeline. Gas hydrate inhibitors are injected based upon:    (a) the calculated/measured hydrate stability zone;    (b) worst case scenarios for pressure and temperature conditions;    (c) water occurrence; and    (d) loss of the inhibitor to any non-aqueous phases present.
In many cases, high safety margins are used to account for uncertainties associated with measuring the above factors, as limited localized monitoring solutions are available along the pipeline; in other words, measurements indicative of, for example, hydrate formation are only available at periodic spatial intervals along the pipeline. This results in a high consumption of an inhibitor liquid, frequent pigging to avoid blocking of pipelines, in addition to the environmental challenges associated with such operations. Due to a high inhibitor dosage requirement, a significant increase in capital expenditure and operational expenditure can arise, in particular at high water cut conditions. Also, despite all these efforts, hydrates do form that can have considerable economic and safety impacts. Thus, systems for early warning and detection of hydrate formation are therefore of considerable value to industry. Moreover, early detection of one or more break-throughs of formation water is also important in industry, on account of production of formation water potentially resulting in sudden increases in water cut and thereby increased risk of hydrate formation arising.
Some localized methods of monitoring hydrate formation along pipelines have been suggested. In a published US patent application no. 2007/0276169, a method of measuring a degree of inhibition of hydrate formation in a fluid is described, namely to determine a susceptibility to gas hydrate formation in the fluid. In the same patent application (see also a published scientific paper Tohidi 2009: Tohidi, Bahman, Antonin Chapoy, and Jinhai Yang. 2009; “Developing a Hydrate-Monitoring System”, SPE Projects Facilities & Construction 4, no. 1 (3). doi:10.2118/125130-PA, http://www.onepetro.org/mslib/servlet/onepetropreview?id=SPE-125130-PA&soc=SPE) a measurement of the dielectric constant for water history has also been suggested as a method of early warning of hydrate formation. A published US patent application no. 2007/0224692 describes an electromagnetically-based method of measuring water and hydrate content in a production fluid. The method is based upon measuring a complex permittivity in the fluid at two or more frequencies. This method is based on bulk measurements, and is not applicable to detecting very thin hydrate coatings at an inner wall of a pipe.
Principles for on-line detecting and monitoring of formation of gas hydrates in pipelines using permittivity measurements for plural frequencies were first suggested and published in the year 1996 by Jakobsen and Folgerø, wherein Kjetil Folgerø is one of the inventors of the present invention:    Jakobsen 1996: Jakobsen, T. “Clathrate hydrates studied by means of time-domain dielectric spectroscopy,” Dr. Scient. Thesis, University of Bergen, 1996. ISBN 82-7406-016-4;    Folgerø 1996: Folgerø, Kjetil. “Coaxial sensors for broad-band complex permittivity measurements of petroleum fluids,” Dr. Scient. Thesis, University of Bergen, 1996. ISBN 82-994032-1-9; and thereafter    Jakobsen 1997: Jakobsen, T., and K. Folgerø. “Dielectric measurements of gas hydrate formation in water-in-oil emulsions using open-ended coaxial probes”. Measurement Science and Technology 8, no. 9 (1997): 1006-1015.
In these publications, it was shown that hydrate formation close to a wall of a sample cell could be monitored using permittivity measurements performing by employing an open-ended coaxial probe. A Norwegian patent no. 312169 describes use of a similar permittivity sensor to monitor water fraction in thin liquid layers. However, such a sensor topology applies a point measurement, namely it is only sensitive to fluid properties in a small spatial region around the probe. This spatially localized sensitivity is a drawback, on account of a single point measurement giving a measurement volume which is so limited such that it may not be representative for an actual hydrate deposition. This limitation is possible to overcome by using a significant number of spatially-distributed point measurement sensors. However, such an approach would be costly to implement on account of each of these sensors requiring a separate corresponding electronics unit in order to measure at all points simultaneously. Moreover, the measurement precision of an open-ended coaxial probe is limited, and cannot be controlled independently of the probe's sensitivity depth and frequency operation range.
A published US patent application no. 2008/0041163 describes a method of detecting particles in a fluid; the method involves passing an ultrasonic signal through the fluid. This method is applicable for identifying gas hydrate nucleation, but it is however not suitable for detecting thin hydrate coatings.
A published U.S. Pat. No. 5,756,898 describes an acoustic method of measuring an effective internal diameter of a pipe containing flowing fluids. The patent application describes a manner in which this method can be applied for measuring hydrate layer thickness or scale/wax deposition. Moreover, a published U.S. Pat. No. 6,470,749 describes another method of measuring a build-up of deposits on an inner surface of a pipeline containing flowing fluid, this method using pulsed ultrasonic Doppler measurements. Further acoustic methods for measuring deposit build-up on insides of pipe walls involve using a guided acoustic wave sensor as described in U.S. Pat. No. 6,568,271, and a similar principle is described in a published U.S. Pat. No. 6,513,385. However, these acoustic methods do not provide a required sensitivity for detecting very thin layers of coating for the case of non-uniform layers with varying bonding between pipe and layer; thus, detection of thin non-uniform coatings associated with hydrate formation is not possible using acoustic methods for providing warnings. Moreover, a depth sensitivity of apparatus and associated measurement techniques in these patents is difficult to control, thereby potentially resulting in unreliable measurements being achieved in practice.
Possible techniques for measuring break-through of formation water include measuring the amount and salinity of water present. A sudden increase in water-content and water-salinity indicates break-through of formation water. The salinity of water can be estimated from the water conductivity, and there exist several apparatuses for measuring water conductivity in water-continuous mixtures. There is, however, a need for more accurate methods to measure the conductivity for oil-continuous mixtures.